This invention relates to the control and optimization of profit from an oil well produced by gas lift.
The typical gas lift system is designed based on a given inflow performance relationship (IPR) and injected gas flow rate. However, with fixed installations, the IPR and injected gas flow rate usually change as a function of time. Once the system is installed, any changes that are made to improve efficiency are generally made at intervals of weeks. This invention employs equipment and techniques which make changes continuously to optimize the profit or production.
The desire to optimize gas lift production is not new. However, the equipment and technology capable to do so are relatively new. A definition for gas lift optimization that most people would agree with is to "obtain the maximum output under specified operating conditions." This definition does not indicate that maximum production is considered to be optimum although it could be. Producing maximum profit should be the goal of optimization. However, since a non-linear economic relationship exists between the amount of gas required to produce a well and the amount of produced oil, as shown in FIG. 2, the maximum profit from a well is not normally achieved when maximum produced oil or liquid is achieved. In addition, the costs of using the gas required and the value of the produced oil must also be considered.
There are several factors that affect the quantity of produced liquid of a gas lift installation. Certainly, the original design of the well is a major factor. The tubing size, depth and location of the injection valves are of prime importance. The reservoir as described by the productivity index or IPR curve is another important factor. However, if the problem is to optimize existing installations, little can be done about these parameters. For a given installation, the following parameters can be controlled such that the given installation can be made to produce the maximum profit of which it is capable. These parameters are injection gas supply, amount of produced liquid, control of injection gas and the method of control of the injection gas. For the purpose of this discussion, it will be assumed that the injection gas supply will always be adequate. This leaves only the measurement of the produced liquid, control of injection gas and the method of control that can be dealt with to optimize the production or profit of a gas lift well.
Because the quantity of produced liquid is used to control the injection gas flow rate, it is necessary to understand the relationship between the quantity of produced liquid and the flow rate of injection gas. FIG. 1 shows two curves. Curve number 1 is the inflow performance (IPR) curve. Curve number 2 is the tubing performance curve for a given size of tubing and a constant gas-liquid ratio. These two curves contain the primary information used in the design and optimization of gas lift wells. The intersection of these two curves at point A represents a stable operating condition. That is, the well will always operate at point A. The intersection at point B is unstable and the well will not operate at this point. Therefore, all of this discussion will be concerning the intersection at point A.
The intersection at point A will change as a function of the IPR curve 1 and the tubing performance curve 2. The IPR curve changes over time. As the reservoir pressure declines, the IPR curve will move downward. First, the following discussion assumes that the tubing performance curve 2 remains constant. Therefore, point A will move to the left which means that less liquid will be produced. Also, the IPR curve is affected by the operation of nearby wells. The reservoir pressure can change daily as a result of nearby wells being taken off or brought on line. If the reservoir pressure increases, the IPR curve will move upward. This means that point A will move to the right and more liquid will be produced. If the reservoir pressure decreases the IPR curve will move downward, point A will move to the left and less liquid will be produced. Therefore, a movement upward of the IPR curve will cause more liquid to be produced and a movement downward will cause less liquid to be produced.
Now, the following discussion assumes that the IPR curve 1 remains constant. The tubing performance curve 2 moves in an up and down direction as a function of the injection gas flow rate and flow line pressure. If the injection gas flow rate is less than that required to produce the maximum quantity of liquid, the tubing performance curve 2 will be moved upward and the intersection (point A) will be moved to the left. This means less liquid produced. As the injection gas flow rate is increased, the tubing performance curve 2 will move downward, point A will move to the right and more liquid will be produced. As the injection gas flow rate is increased, the tubing performance curve 2 will continue to move downward and more liquid will be produced. However, this continued increase in produced liquid does have a limit. When this limit is reached, any further increase in injection gas flow rate will cause the intersection at point A to move back to the left and in an upward direction and less liquid will be produced. Actually, the shape of the tubing performance curve 2 changes more than the entire curve shifting up and down. Therefore as can readily be seen, if the injection gas flow rate exceeds a given value, any further increases will cause a reduction in produced liquid.
From the above discussion, it can be seen that in order to optimize a gas lift well, the intersection of the IPR curve 1 and the tubing performance curve 2 or point A must be controlled. Actually, relatively little can be done with IPR curve. Therefore, the major element of control lies in the control of the tubing performance curve (curve No. 2). And after an installation is complete, only the injection gas flow rate can be controlled. Therefore, the present invention is directed to the control of the injection gas flow rate.